U.S. patent application number 13/288049 was filed with the patent office on 2012-05-10 for method for characterizing the fracture network of a fractured reservoir and method for developing it.
Invention is credited to Bernard Bourbiaux, Andre FOURNO.
Application Number | 20120116740 13/288049 |
Document ID | / |
Family ID | 44123420 |
Filed Date | 2012-05-10 |
United States Patent
Application |
20120116740 |
Kind Code |
A1 |
FOURNO; Andre ; et
al. |
May 10, 2012 |
METHOD FOR CHARACTERIZING THE FRACTURE NETWORK OF A FRACTURED
RESERVOIR AND METHOD FOR DEVELOPING IT
Abstract
The invention is a method for constructing a representation of a
fluid reservoir traversed by a fracture network and by at least one
well. The reservoir is discretized into a set of grid cells and the
fractures are characterized by statistical parameters from
observations of the reservoir. An equivalent permeability tensor
and an average fracture opening is constructed from an image
representative of the fracture network delimiting porous blocks and
fractures is then deduced from the statistical parameters. A first
elliptical boundary zone centered on the well and at least a second
elliptical boundary zone centered on the well which form an
elliptical ring with the elliptical boundary of the first zone are
defined around the well. The image representative of the fracture
network is simplified in a different manner for each of the zones
which is used to construct the representation of the fluid
reservoir.
Inventors: |
FOURNO; Andre;
(Rueil-Malmaison, FR) ; Bourbiaux; Bernard; (Rueil
Malmaison, FR) |
Family ID: |
44123420 |
Appl. No.: |
13/288049 |
Filed: |
November 3, 2011 |
Current U.S.
Class: |
703/10 |
Current CPC
Class: |
E21B 43/00 20130101;
E21B 43/26 20130101; E21B 49/00 20130101; E21B 49/008 20130101 |
Class at
Publication: |
703/10 |
International
Class: |
G06G 7/57 20060101
G06G007/57 |
Foreign Application Data
Date |
Code |
Application Number |
Nov 10, 2010 |
FR |
10/04.398 |
Claims
1-11. (canceled)
12. A method for optimizing the development of a fluid reservoir
traversed by a fracture network and by at least one well, wherein a
representation of the fluid reservoir is constructed, the reservoir
is discretized into a set of cells and the fractures are
characterized by statistical parameters from observations of the
reservoir, comprising: a) determining from the statistical
parameters an equivalent permeability tensor and an average opening
for the fractures from which an image representative of the
fracture network delimiting porous blocks and fractures is
constructed; b) determining from the tensor a direction of flow of
the fluid around the well; c) defining around the well a first
elliptical boundary zone centered on the well and containing the
well and at least a second elliptical boundary zone centered on the
well which forms an elliptical ring with the elliptical boundary of
the first zone with the at least a second elliptical zone being
oriented in the direction of flow of the fluid; d) simplifying the
image representative of the fracture network in a different manner
in each of the zones; e) using the simplified image to construct a
representation of the fluid reservoir; and f) using the
representation of the fluid reservoir and a flow simulator to
optimize the development of the fluid reservoir.
13. A method as claimed in claim 12, wherein the statistical
parameters are selected from among the parameters: fracture
density, fracture length, fracture orientation, fracture
inclination, fracture opening and fracture distribution within the
reservoir.
14. A method as claimed in claim 12, wherein an aspect ratio is
determined for each zone which is defined from lengths of axes of
an ellipse making up the boundary of each zone to reproduce a flow
anisotropy around the well with the zones being constructed in
accordance with the aspect ratio.
15. A method as claimed in claim 13, wherein an aspect ratio is
determined for each zone which is defined from lengths of axes of
an ellipse making up the boundary of each zone to reproduce a flow
anisotropy around the well with the zones being constructed in
accordance with the aspect ratio.
16. A method as claimed in claim 14, wherein the aspect ratio is
determined by values of the permeability tensor.
17. A method as claimed in claim 15, wherein the aspect ratio is
determined by values of the permeability tensor.
18. A method as claimed in claim 12, wherein a distance is defined
between boundaries between the zones to give equal weight to each
zone in terms of a pressure difference recorded in each zone under
permanent flow conditions.
19. A method as claimed in claim 13, wherein a distance is defined
between boundaries between the zones to give equal weight to each
zone in terms of a pressure difference recorded in each zone under
permanent flow conditions.
20. A method as claimed in claim 14, wherein a distance is defined
between boundaries between the zones to give equal weight to each
zone in terms of a pressure difference recorded in each zone under
permanent flow conditions.
21. A method as claimed in claim 15, wherein a distance is defined
between boundaries between the zones to give equal weight to each
zone in terms of a pressure difference recorded in each zone under
permanent flow conditions.
22. A method as claimed in claim 16, wherein a distance is defined
between boundaries between the zones to give equal weight to each
zone in terms of a pressure difference recorded in each zone under
permanent flow conditions.
23. A method as claimed in claim 17, wherein a distance is defined
between boundaries between the zones to give equal weight to each
zone in terms of a pressure difference recorded in each zone under
permanent flow conditions.
24. A method as claimed in claim 18, wherein the distance is
defined by setting lengths of one of two axes of two successive
ellipses at values in geometric progression of a constant
ratio.
25. A method as claimed in claim 19, wherein the distance is
defined by setting lengths of one of two axes of two successive
ellipses at values in geometric progression of a constant
ratio.
26. A method as claimed in claim 20, wherein the distance is
defined by setting lengths of one of two axes of two successive
ellipses at values in geometric progression of a constant
ratio.
27. A method as claimed in claim 21, wherein the distance is
defined by setting lengths of one of two axes of two successive
ellipses at values in geometric progression of a constant
ratio.
28. A method as claimed in claim 22, wherein the distance is
defined by setting lengths of one of two axes of two successive
ellipses at values in geometric progression of a constant
ratio.
29. A method as claimed in claim 23, wherein the distance is
defined by setting lengths of one of two axes of two successive
ellipses at values in geometric progression of a constant
ratio.
30. A method as claimed in claim 12, wherein three zones are
constructed with a first zone containing the well with no
simplification of the image being provided, a second zone is
constructed in contact with the first zone wherein a first
simplification of the image is carried out and a third zone is
constructed in contact with the second zone wherein a second
simplification of the image is carried out with the second
simplification being more significant than the first
simplification.
31. A method as claimed in claim 30, wherein the second and third
zones are divided into sub-zones by the steps: dividing the second
zone into a number of sub-zones equal in number to a number of
blocks of cells present in the second zone with a block of cells
designating a vertical stack of cells; and dividing the third zone
by the steps of dividing every degree a boundary of the third zone
with each degree defining 360 arcs, defining a sub-zone by
connecting end points of each of the arcs to a center of an ellipse
forming the boundary, for each of the sub-zones, calculating an
equivalent fracture permeability tensor from which an orientation
of the flows in the sub-zone is determined, comparing equivalent
fracture permeability values and flow orientation between
neighboring sub-zones, and grouping neighboring sub-zones together
into a single sub-zone when a difference between the permeability
values is below a first threshold and when a difference between the
flow orientations is below a second threshold.
32. A method as claimed in claim 12, wherein the image is
simplified by the steps: constructing a fracture network equivalent
to the image, by a Warren and Root representation wherein the
network has fracture spacings s.sub.1.sup.fin, s.sub.2.sup.fin in
two orthogonal directions of principal permeability, by a fracture
opening parameter e.sup.fin, by fracture conductivities
C.sub.f1.sup.fin and C.sub.f2.sup.fin and a permeability kmfin of a
matrix medium between fractures; simplifying the equivalent
fracture network by a network fracture spacing coefficient whose
value is less than a value Gmax-zone defined for each of the zones
to guarantee connectivity between simplified zones and
non-simplified zones.
33. A method as claimed in claim 31 wherein, for a given sub-zone,
value Gmax-zone is equal to: G max - zone = DLM 6 Max ( s 1 fin , s
2 fin ) ##EQU00009## with: DLM being a minimum lateral dimension of
the given sub-zone; and s.sub.1.sup.fin, s.sub.2.sup.fin being
fracture spacings in the Warren and Root representation.
34. A method as claimed in claim 12, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
35. A method as claimed in claim 13, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
36. A method as claimed in claim 14, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
37. A method as claimed in claim 16, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
38. A method as claimed in claim 18, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
39. A method as claimed in claim 24, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
40. A method as claimed in claim 30, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
41. A method as claimed in claim 31, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
42. A method as claimed in claim 32, comprising: repeating a) while
modifying the statistical parameters to minimize a difference
between a well test result and a well test simulation result from
the simplified image; associating with each one of the cells at
least one equivalent permeability value and an average opening
value for the fractures with the values being determined from the
modified statistical parameters; simulating fluid flows in the
reservoir by a flow simulator equivalent permeability values and
average opening values of the fractures associated with each of the
cells; selecting a production scenario optimizing the reservoir
production by the fluid flow simulation; and developing the
reservoir according to the scenario to optimize reservoir
production.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates to development of underground
reservoirs, such as hydrocarbon reservoirs comprising a fracture
network. In particular, the invention relates to a method for
characterizing the fracture network and constructing a
representation of the reservoir. A method using this representation
to optimize the management of such a development through a
prediction of the fluid flows likely to occur through the medium to
simulate hydrocarbon production according to various production
scenarios.
[0003] 2. Description of the Prior Art
[0004] The petroleum industry, and more precisely exploration and
development of reservoirs, notably petroleum reservoirs, require
knowledge of the underground geology which is as perfect as
possible so as to efficiently provide evaluation of reserves,
production modelling or development management. In fact,
determining the location of a production well or of an injection
well, the drilling mud composition, the completion characteristics,
selection of a hydrocarbon recovery method (such as waterflooding
for example) and of the parameters required for implementing this
method (such as injection pressure, production flow rate, etc.)
requires good knowledge of the reservoir. Reservoir knowledge
notably means knowledge of the petrophysical properties of the
subsoil at any point in space.
[0005] The petroleum industry has therefore combined for a long
time field (in-situ) measurements with experimental modelling
(performed in the laboratory) and/or numerical modelling (using
softwares). Petroleum reservoir modelling is a technical stage that
is essential for any reservoir exploration or development
procedure. The goal of modelling is to provide a description of the
reservoir.
[0006] Fractured reservoirs are an extreme type of heterogeneous
reservoirs comprising two very different media, a matrix medium
containing the major part of the oil in place and having a low
permeability, and a fractured medium representing less than 1% of
the oil in place and highly conductive. The fractured medium itself
can be complex, with different sets of fractures characterized by
their respective density, length, orientation, inclination and
opening.
[0007] Those in charge of the development of fractured reservoirs
need to perfectly know the role of fractures. What is referred to
as a "fracture" is a plane discontinuity of very small thickness in
relation to the extent thereof, representing a rupture plane of a
rock of the reservoir. On the one hand, knowledge of the
distribution and of the behavior of these fractures allows
optimizing the location and the spacing between wells to be drilled
through the oil-bearing reservoir. On the other hand, the geometry
of the fracture network conditions the fluid displacement, on the
reservoir scale as well as the local scale where it determines
elementary matrix blocks in which the oil is trapped. Knowing the
distribution of the fractures is therefore also very helpful at a
later stage to the reservoir engineer who wants to calibrate the
models which have been constructed to simulate the reservoirs in
order to reproduce or to predict the past or future production
curves. Geosciences specialists therefore have three-dimensional
images of reservoirs allowing locating a large number of
fractures.
[0008] Thus, in order to reproduce or to predict (that is
"simulate") the production of hydrocarbons when starting production
of a reservoir according to a given production scenario
(characterized by the position of the wells, the recovery method,
etc.), reservoir engineers use a computing software referred to as
reservoir simulator (or flow simulator) that calculates the flows
and the evolution of the pressures within the reservoir represented
by the reservoir model. The results of these computations enable
prediction and optimization of the reservoir in terms of flow rate
and/or of amount of hydrocarbons recovered. Calculation of the
reservoir behavior according to a given production scenario
constitutes a "reservoir simulation".
[0009] There is a well-known method for optimizing the development
of a fluid reservoir traversed by a fracture network, wherein fluid
flows through the reservoir are simulated through simplified but
realistic modelling of the reservoir. This simplified
representation is referred to as "double-medium approach",
described by Warren J. E. et al. in "The Behavior of Naturally
Fractured Reservoirs", SPE Journal (September 1963), 245-255. This
technique considers the fractured medium as two continua exchanging
fluids with one another: matrix blocks and fractures which is
referred to as a "double medium" or "double porosity" model. Thus,
"double-medium" modelling of a fractured reservoir discretizes the
reservoir into two superposed sets of cells (referred to as grids)
making up the "fracture" grid and the "matrix" grid. Each
elementary volume of the fractured reservoir is thus conceptually
represented by two cells, a "fracture" cell and a "matrix" cell,
coupled to one another (i.e. exchanging fluids). In the reality of
the fractured field, these two cells represent all of the matrix
blocks delimited by fractures present at this point of the
reservoir. In fact, in most cases, the cells have hectometric
lateral dimensions (commonly 100 or 200 m) considering the size of
the fields and the limited possibilities of simulation softwares in
terms of computing capacity and time. The result thereof is that,
for most fractured fields, the fractured reservoir elementary
volume (cell) comprises innumerable fractures forming a complex
network that delimits multiple matrix blocks of variable dimensions
and shapes according to the geological context. Each constituent
real block exchanges fluids with the surrounding fractures at a
rate (flow rate) that is specific thereto because it depends on the
dimensions and on the shape of this particular block.
[0010] In the face of such a geometrical complexity of the real
medium, the approach is for each reservoir elementary volume
(cell), in representing the real fractured medium as a set of
matrix blocks that are all identical, parallelepipedic, delimited
by an orthogonal and regular network of fractures oriented in the
principal directions of flow: For each cell, the so-called
"equivalent" permeabilities of this fracture network are thus
determined and a matrix block referred to as "representative" (of
the real (geological) distribution of the blocks), single and of
parallelepipedic shape, is defined. It is then possible to
formulate and to calculate the matrix-fracture exchange flows for
this "representative" block and to multiply the result by the
number of such blocks in the elementary volume (cell) to obtain the
flow on the scale of this cell.
[0011] It can however be noted that calculation of the equivalent
permeabilities requires knowledge of the flow properties (that is
the conductivities) of the discrete fractures of the geological
model.
[0012] It is therefore necessary, prior to constructing this
equivalent reservoir model (referred to as "double-medium reservoir
model") as described above, to simulate the flow responses of some
wells (transient or pseudo-permanent flow tests, interferences,
flow measurement, etc.) on models extracted from the geological
model giving a discrete (realistic) representation of the fractures
supplying these wells. Adjustment of the simulated pressure/flow
rate responses on the field measurements allows the conductivities
of the fracture families to be calibrated. Although it covers a
limited area (drainage area) around the well only, such a well test
simulation model still comprises a very large number of calculation
nodes if the fracture network is dense. Consequently, the size of
the systems to be solved and/or the computation time often remain
prohibitive.
[0013] To overcome this difficulty, the invention comprises a
simplification of the fracture networks on the local scale of the
well drainage area, so as to be able to simulate the fractured
reservoir well tests and thus to calibrate the conductivities of
the fracture families. This hydraulic calibration of the fractures
leads to a set of parameters characterizing the fracture network
(or fracture model). This fracture model is thereafter used to
construct a double-medium flow model on the reservoir scale.
SUMMARY OF THE INVENTION
[0014] The invention thus relates to a method for optimizing the
development of a fluid reservoir traversed by a fracture network
and by at least one well, wherein a representation of the fluid
reservoir is constructed. The reservoir is discretized into a set
of cells and the fractures are characterized by statistical
parameters (PSF) from observations of the reservoir. The method
comprises the following stages: [0015] a) deducing from the
statistical parameters (PSF) an equivalent permeability tensor and
an average opening for the fractures, from which an image
representative of the fracture network delimiting porous blocks and
fractures is constructed; [0016] b) deducing from the tensor a
direction of flow of the fluid around the well; [0017] c) defining
around the well a first elliptical boundary zone centered on the
well and containing the well, and at least a second elliptical
boundary zone centered on the well and forming an elliptical ring
with the elliptical boundary of the first zone, the zones being
oriented in the direction of flow of the fluid; [0018] d)
simplifying the image representative of the fracture network in a
different manner in each one of the zones; [0019] e) using the
simplified image to construct the representation of the fluid
reservoir; and [0020] f) using the representation of the fluid
reservoir and a flow simulator to optimize the development of the
fluid reservoir.
[0021] According to the invention, the statistical parameters (PSF)
can be selected from among the following parameters: fracture
density, fracture length, fracture orientation, fracture
inclination, fracture opening and fracture distribution within the
reservoir.
[0022] According to an embodiment, an aspect ratio is determined
for each zone, defined from the lengths of the axes of the ellipse
making up the boundary of the zone, so as to reproduce a flow
anisotropy around the well, and the zones are constructed so as to
respect the aspect ratio. This aspect ratio can be determined by
the principal values of the permeability tensor.
[0023] According to an embodiment, a distance is defined between
the boundaries between zones, so as to give an equal weight to each
zone in terms of pressure difference recorded in each zone under
permanent flow regime conditions. This distance can be defined by
setting the lengths of one of the two axes of two successive
ellipses at values in geometric progression of constant ratio.
[0024] According to another embodiment, three zones are
constructed, a first zone (ZNS) containing the well, wherein no
image simplification is provided, a second zone (ZP) in contact
with the first zone, wherein a first image simplification is
carried out, and a third zone (ZL) in contact with the second zone,
wherein a second image simplification is carried out with the
second simplification being more significant than the first
one.
[0025] Advantageously, the second and third zones can be divided
into sub-zones by applying the following stages:
the second zone is divided into a number of sub-zones equal to a
number of blocks of cells present in the zone with a block of cells
designating a vertical pile of cells; the third zone is divided by
carrying out the following stages:
[0026] dividing every degree of the boundary of the third zone into
360 arcs;
[0027] defining a sub-zone by connecting end points of each of the
arcs to the center of the ellipse forming the boundary;
[0028] for each one of the sub-zones, calculating an equivalent
fracture permeability tensor from which an orientation of the flows
in the sub-zone is determined;
[0029] comparing the equivalent fracture permeability values and
the flow orientation between neighboring sub-zones; and
[0030] grouping neighboring sub-zones together into a single
sub-zone when a difference between the permeability values is below
a first threshold and when a difference between the flow
orientations is below a second threshold.
[0031] According to the invention, the image can be simplified by
carrying out the following stages:
[0032] constructing a fracture network equivalent of the image
(RFE), by means of a so-called Warren and Root representation,
wherein the network is characterized by fracture spacings
(s.sub.1.sup.fin, s.sub.2.sup.fin) in two orthogonal directions of
principal permeability, by a fracture opening parameter
(e.sup.fin), by fracture conductivities (C.sub.f1.sup.fin and
C.sub.f2.sup.fin) and a permeability (k.sub.m.sup.fin) of a matrix
medium between fractures; and
[0033] simplifying the equivalent fracture network (RFE) by a
network fracture spacing coefficient (G) whose value is less than a
value G.sub.max-zone defined on each of the zones in order to
guarantee sufficient connectivity between simplified zones and
non-simplified zones.
[0034] Value G.sub.max-zone can be defined as follows for a given
sub-zone:
G max - zone = DLM 6 Max ( s 1 fin , s 2 fin ) ##EQU00001##
with: [0035] DLM minimum lateral dimension of the given sub-zone;
[0036] s.sub.1.sup.fin, s.sub.2.sup.fin: fracture spacings in the
so-called Warren and Root representation.
[0037] Finally, the invention also relates to a method for
optimizing the management of a reservoir. It comprises the
following stages:
[0038] repeating stage a) while modifying the statistical
parameters (PSF) so as to minimize a difference between a well test
result and a well test simulation result from the simplified
image;
[0039] associating with each one of the cells at least one
equivalent permeability value and an average opening value for the
fractures with the values being determined from the modified
statistical parameters (PSF);
[0040] simulating fluid flows in the reservoir with a flow
simulator, and the equivalent permeability values and the average
opening values of the fractures associated with each one of the
cells;
[0041] selecting a production scenario allowing optimizing the
reservoir production with the fluid flow simulation; and
[0042] developing the reservoir according to the scenario allowing
optimizing the reservoir production.
BRIEF DESCRIPTION OF THE DRAWINGS
[0043] Other features and advantages of the method according to the
invention will be clear from reading the description hereafter of
embodiments given by way of non limitative example, with reference
to the accompanying figures wherein:
[0044] FIG. 1 illustrates the various stages of the method
according to the invention;
[0045] FIG. 2 illustrates a realization of a fracture/fault network
on the reservoir scale;
[0046] FIG. 3 illustrates an initial discrete fracture network
(DFN);
[0047] FIG. 4 illustrates a so-called Warren and Root equivalent
fracture network (RFE);
[0048] FIG. 5 illustrates the creation of zones and sub-zones
necessary for simplification of the equivalent fracture network
(RFE);
[0049] FIG. 6 illustrates a simplified equivalent fracture network
(RFES) according to the invention.
DETAILED DESCRIPTION OF THE INVENTION
[0050] The method according to the invention for optimizing the
development of a reservoir using the method of the invention for
characterizing the fracture network comprises four stages, as
illustrated in FIG. 1:
[0051] 1--Discretization of the reservoir into a set of cells
(MR)
[0052] 2--Modelling of the fracture network (DFN, RFE, RFES)
[0053] 3--Simulation of the fluid flows (SIM) and optimization of
the reservoir production conditions (OPT)
[0054] 4--Optimized (global) development of the reservoir
(EXPLO)
[0055] 1--Discretization of the Reservoir into a Set of Cells
(MR)
[0056] The petroleum industry has combined for a long time field
(in-situ) measurements with experimental modelling (performed in
the laboratory) and/or numerical modelling (using softwares).
Petroleum reservoir modelling thus is an essential technical stage
with a view to reservoir exploration or development. The goal of
such modelling is to provide a description of the reservoir,
characterized by the structure/geometry and the petrophysical
properties of the geological deposits or formations therein.
[0057] These modellings are based on a representation of the
reservoir as a set of cells. Each cell represents a given volume of
the reservoir and makes up an elementary volume of the reservoir.
The cells in their entirety make up a discrete representation of
the reservoir which is referred to as geological model.
[0058] Many software tools are known allowing construction of such
reservoir models from data (DG) and measurements (MG) relative to
the reservoir.
[0059] FIG. 2 illustrates a two-dimensional view of a reservoir
model. The fractures are represented by lines. The cells are not
shown.
[0060] 2--Modelling the Fracture Network
[0061] In order to take into account the role of the fracture
network in the simulation of flows within the reservoir, it is
necessary to associate with each of these elementary volumes (cells
of the reservoir model) a modelling of the fractures.
[0062] Thus, one object of the invention relates to a method for
constructing a representation of a fluid reservoir traversed by a
fracture network and by at least one well. This method comprises
discretizing the reservoir into a set of cells (stage 1 described
above). The method then comprises the following stages: [0063] a.
characterizing the fractures by statistical parameters (PSF) from
reservoir observations; [0064] b. determining from these
statistical parameters (PSF) an equivalent permeability tensor and
an average opening of the fractures, from which an image
representative of the fracture network delimiting porous blocks and
fractures is constructed; [0065] c. determining from the tensor a
direction of flow of the fluid around the well; [0066] d. defining
around the well a first elliptical boundary zone centered on the
well and containing the well and at least a second elliptical
boundary zone centered on the well within an inner boundary merging
with the elliptical boundary of the first zone with the zones being
oriented in the direction of flow of the fluid; [0067] e.
simplifying the image representative of the fracture network in
each cell belonging to at least one zone; [0068] f. repeating b)
while modifying the statistical parameters (PSF) to minimize the
difference between the well test result and the well test
simulation result from the simplified image; and [0069] g.
associating with each cell at least one equivalent permeability
value and a fracture average opening value with these values being
determined from the modified statistical parameters (PSF).
[0070] These stages are described in detail hereafter.
[0071] Fracture Characterization
[0072] The statistical reservoir characterization is based upon
carrying out direct and indirect reservoir observations (OF). This
characterization uses 1) well cores extracted from the reservoir,
on which a statistical study of the intersected fractures is
performed, 2) outcrops which are characteristic of the reservoir
which has the advantage of providing a large-scale view of the
fracture network, and 3) seismic images allowing the identification
of major geological events.
[0073] These measurements allow characterizing the fractures by
statistical parameters (PSF) which are their respective density,
length, orientation, inclination and opening, and their
distribution within the reservoir.
[0074] At the end of this fracture characterization stage,
statistical parameters (PSF) are obtained describing the fracture
networks from which realistic images of the real (geological)
networks can be reconstructed (generated) on the scale of each cell
of the reservoir model considered (simulation domain).
[0075] The goal of characterization and modelling of the reservoir
fracture network is to provide a fracture model validated on the
local flows around the wells. This fracture model is then extended
to the reservoir scale in order to achieve production simulations.
Flow properties are therefore associated with each cell of the
reservoir model (MR) (permeability tensor, porosity) of the two
media (fracture and matrix).
[0076] These properties can be determined either directly from the
statistical parameters (PSF) describing the fracture networks, or
from a discrete fracture network (DFN) obtained from the
statistical parameters (PSF).
[0077] Constructing a Discrete Fracture Network (DFN)--FIGS. 2 and
3
[0078] Starting from a reservoir model of the reservoir being
studied, a detailed representation (DFN) of the internal complexity
of the fracture network which is as accurate as possible in
relation to the direct and indirect reservoir observations, is
associated with each cell. FIG. 2 illustrates a realization of a
fracture/fault network on the scale of a reservoir. Each cell of
the reservoir model thus represents a discrete fracture network
delimiting a set of porous matrix blocks, of irregular shape and
size, delimited by fractures. Such an image is shown in FIG. 3.
This discrete fracture network constitutes an image representative
of the real fracture network delimiting the matrix blocks.
[0079] Constructing a discrete fracture network in each cell of a
reservoir model can be achieved using known modelling softwares,
such as the FRACAFlow.RTM. software (IFP, France). These softwares
use the statistical parameters determined in the fracture
characterization stage.
[0080] The next stage determines the flow properties of the initial
fractures (C.sub.f, e) and then calibrates these properties by well
test simulations on discrete local flow models obtained from the
realistic image of the real (geological) fracture network on the
reservoir scale. Although it covers a limited area (drainage area)
around the well only, such a well test simulation model still
comprises a very large number of calculation nodes if the fracture
network is dense. Consequently, the size of the systems to be
solved and/or the computation time often remain prohibitive, hence
the necessity to use a fracture network simplification
procedure.
[0081] Fracture Network Simplification--FIG. 5
[0082] Because of its extreme geometrical complexity, the fracture
network obtained in the previous stage, representative of the real
fractured reservoir, cannot be used to simulate, that is reproduce
and/or predict, the local flows around the well.
[0083] In order to overcome this obstacle, the method according to
the invention uses a procedure based on the division of the
simulation domain (that is the reservoir model) into at least three
types of zone around each well (FIG. 5):
[0084] A first zone wherein no fracture network simplification is
performed. This zone contains the well and its center. It is
denoted by ZNS (non-simplified zone);
[0085] A second zone which is in contact with the first zone,
wherein a moderate simplification of the fracture network is
performed. This zone is denoted by ZP (zone to be simplified close
to the well);
[0086] A third zone, in contact with the second zone, wherein a
significant simplification of the fracture network is performed.
This zone is denoted by ZL (zone at a distance from the well).
[0087] The invention is not limited to the definition of three
zones. It is also possible to divide the domain into n zones in
which the simplification of the network increases from zone 1 (ZNS)
to zone n (the furthest from the well). It is thus possible to
create a zone ZNS, n1 zones of type ZP and n2 zones of type ZL.
[0088] Constructing the Zones--FIG. 5
[0089] The goal of fracture network modelling is to simulate the
well flow responses (transient or pseudo-permanent flow tests,
interferences, flow measurement, etc.). It consists for example in
simulating the oil production via each well drilled through the
reservoir.
[0090] For each well, each zone is defined according to an exterior
boundary forming an ellipse centered on the well. The three zones
are thus concentric and with elliptical boundaries. The two
simplified zones ZP and ZL have inner boundaries corresponding to
the outer boundary of the respective zones ZNS and ZP. Except for
the non-simplified zone, the zones thus are elliptical rings
centered on the well. To construct each zone, it is a must to
define:
[0091] the orientation of the ellipse, that is the direction of the
major axis of the ellipse (perpendicular to the direction of the
minor axis); and
[0092] the dimensions of the ellipse, that is the length of the
axes.
[0093] Their orientation is determined by the directions of flow
determined from a calculation of equivalent permeabilities on zone
ZNS. This type of equivalent permeability calculation is well
known. It is possible to use, for example, the numerical method of
calculating fractured media equivalent properties, implemented in
the FracaFlow software (IFP Energies nouvelles, France) and
described hereafter.
[0094] According to this method, a permeability tensor
representative of the flow properties of the discretized fracture
network (DFN) can be obtained via two upscaling methods.
[0095] The first method which is an analytical method referred to
as local analytical upscaling, is based on an analytical approach
described in the following documents:
[0096] Oda M. (1985): Permeability Tensor for Discontinuous Rock
Masses, Geotechnique Vol 35, 483-495; and
[0097] Patent application EP 2 037 080.
[0098] It affords the advantage of being very fast. Its range of
application is however limited to well connected fracture networks.
In the opposite case, major errors on the permeability tensor can
be observed.
[0099] The second method which is a numerical method referred to as
local numerical upscaling, is described in the following
documents:
[0100] Bourbiaux, B., et al., 1998, "A Rapid and Efficient
Methodology to Convert Fractured Reservoir Images into a
Dual-Porosity Model", Oil & Gas Science and Technology, Vol.
53, No. 6, November-December 1998, 785-799.
[0101] French Patent 2.757.947, corresponding to U.S. Pat. No.
6,023,656 for equivalent permeabilities, and French Patent
2,757,957, corresponding to U.S. Pat. No. 6,064,944, for equivalent
block dimensions.
[0102] It is based on the numerical solution of the equations of
flow on a discrete grid of the fracture network for various
boundary conditions of the computation block considered. The
equivalent permeability tensor is obtained by identification of the
ratios between flow rate and pressure drop at the boundaries of the
computation block. This approach, which is more expensive than the
previous one, has the advantage of characterizing a given network
(even weakly connected well).
[0103] According to an embodiment, it is possible to select one or
the other of the two previous methods to optimize the accuracy and
speed of the computations, by applying the method described in EP
Patent Application 2,037,080, based on the computation of a
connectivity index.
[0104] This technique allows, in a preliminary stage, determination
of the permeability tensors of some cells of the reservoir model
surrounding the well, and is considered to be representative of the
flow of ZNS. Diagonalization of these permeability tensors provides
the eigenvectors oriented in the principal directions of flow that
are being sought. It is then possible to orient the elliptical
domain ZNS centered on the well along the semi-major axis of the
permeability ellipse determined by the preliminary
computations.
[0105] Then, in order to define the dimensions of the ellipse, an
aspect ratio is defined for this ellipse, as well as a distance
between concentric ellipses (distance between the inner and outer
elliptical boundaries of a given concentric ring):
[0106] aspect ratio of the ellipses. By denoting by L.sub.max the
half-length of the major axis of the ellipse, and by L.sub.min the
half-length of the minor axis of the ellipse, this aspect ratio is
defined by L.sub.max/L.sub.min. It should not be fixed arbitrarily
but, and to the contrary, it should be selected to reproduce the
flow anisotropy. The calculated equivalent permeability tensor can
be used to determine the orientation. If the principal values of
this tensor are denoted by K.sub.min and K.sub.max, then the
ellipses are oriented in the principal permeability directions with
an aspect ratio L.sub.max/L.sub.min equal to the square root of
ratio K.sub.max/K.sub.min:
L max L min = K max K min ##EQU00002##
[0107] which is a distance between concentric ellipses (boundaries
between zones).
A dimensioning criterion in accordance with a modelling accuracy
uniformly distributed over the simulation domain sets the
half-lengths of the major axis L.sub.max (or of the minor axis
L.sub.min) of 2 successive ellipses i+1 and i at values in
geometric progression of constant ratio r (equal to 2 for example),
that is:
L max ( i + 1 ) L max ( i ) = L min ( i + 1 ) L min ( i ) = r ,
##EQU00003##
for any I, with initialization to the value L.sub.max0 of the
non-simplified zone. This rule allows giving an equal weight to
each zone I (i=1 to n) in terms of pressure difference observed in
each ring under permanent flow regime conditions.
[0108] Once this global dimensioning is achieved, the sub-zone
delimitation and simplification procedures are implemented which
are also based on the methods of calculating the equivalent
properties of fractured media.
[0109] Constructing Sub-Zones in Each Zone--FIG. 5
[0110] Each zone, except zone ZNS, is then subdivided into
sub-zones (ssZP, ssZL1, ssZL2) within which simplification of the
fracture network is performed. The number of sub-zones per zone
depends on the type of the zone (ZNS, ZP or ZL) and on the
heterogeneity thereof. Thus:
[0111] Zone ZNS is to be kept intact (non simplified); no sub-zone
is created therein,
[0112] The zones to be simplified that are the closest to a well
(ZP type zones) require particular attention. In order to correctly
model the local variations of the flow properties in this zone,
zones ZP are divided into a number of sub-zones equal to the number
of blocks of cells present in zones ZP. The term "block of cells"
is used to designate a "stack" of vertical cells (of CPG type
(Corner Point Grid) for example) of the reservoir model, delimited
by the same sub-vertical upright poles. They are therefore no
equivalent blocks;
[0113] The zones to be simplified that are the furthest from a well
(ZL type zones) are concentric elliptical rings that cover
increasingly large surfaces as the distance from the well
increases. Being further away from the wells, it is acceptable to
be less accurate regarding heterogeneities detection than in the
case of ZP type zones. The heterogeneity of the flow properties of
a ZL type zone remains however the principal factor controlling the
subdivision into sub-zones. To sample a ZL type zone, an angular
scan centered on the well is performed on the outer elliptical
limit separating the zone ZL being considered from its outer
neighbor. For every degree, a block of cells is selected. Thus,
zone ZL is characterized by at most 360 blocks. For each block, the
equivalent fracture permeability tensor is calculated. This tensor
allows characterizing the dynamic properties of the fracture
network of the block being studied. The permeability values and the
flow orientation obtained are then compared among neighboring
blocks. If the properties of two neighboring blocks are close,
these two blocks are considered to belong to the same sub-zone. In
the opposite case (20% difference on the principal permeability
values or 10 degree difference on the principal permeability
directions for example), the two blocks are assigned to different
sub-zones thus defined. The outer limit of the zone ZL being
considered is divided into arcs of elliptical shape (FIG. 1). The
sub-zones are then obtained by connecting the end points of each
arc to the center (well) of the ellipse (dotted lines in FIG. 5).
Each sub-zone is thus defined as the area contained between the
intra-zone radial partition (dotted lines) and the inter-zone
elliptical limits (full line).
[0114] As mentioned above, the delimitation of the sub-zones (limit
points of the inter-zone elliptical boundary arcs) is based on the
comparison of the equivalent permeabilities calculated on the
"neighboring" blocks marking these arcs. The analytical method of
computing the equivalent permeabilities is preferably used because
the goal is, in this case, to determine whether a block has the
same dynamic behavior as the neighboring block. Although, for a
weakly connected network, the analytical approach provides
erroneous results, errors are systematic, which are similar from
one block to the next, which allows comparison of the results
between blocks which clearly does not require a high accuracy
considering the simple zone definition objective. Thus, the
analytical approach is totally justified, with the considerable
advantage of enabling must faster calculations, thus guaranteeing
practical feasibility.
[0115] Simplifying the Fracture Network in the Sub-Zones (RFE,
RFES)
[0116] Once the zones divided into sub-zones, the upscaling
calculations allow replacement of the fracture network of these
sub-zones by a simplified network having the same flow properties
as the initial network. In this case, and unlike what has been
written above, the calculation of the equivalent fracture
permeability tensor has to be as accurate as possible.
[0117] In order to make the most of the advantages afforded by the
two upscaling methods, the permeability tensor is determined by one
or the other of these two methods for example, according to the
selection procedure described in document EP Patent 2,037,080,
based on the value of the connectivity index of the fracture
network. This index, representative of the ratio between the number
of intersections between fractures and the number of fractures, is
calculated for each unit of the block being considered (that is
2D). Its value allows considering the network as very well
connected, weakly/badly connected or non-connected. The upscaling
method is then selected as follows Delorme, M., Atfeh, B., Allken,
V. and Bourbiaux, B. 2008, Upscaling Improvement for Heterogeneous
Fractured Reservoir Using a Geostatistical Connectivity Index,
edited in Geostatistics 2008, VIII International Geostatistics
Congress, Santiago, Chile:
[0118] A well-connected network in this case is characterized by a
connectivity index close to or exceeding 3 (at least 3
intersections per fracture of the network on average). The
analytical upscaling method is selected because its accuracy is
guaranteed considering the good connectivity of the network with
the essential additional advantage of fastness;
[0119] A weakly/badly-connected network in this case is when the
connectivity index ranges between 1 and 3 (which corresponds to a
number of fracture intersections ranging between one and three
times the number of fractures), and the numerical upscaling method
is selected to reliably calculate the permeability tensor;
[0120] When the network is very poorly or even not connected, which
occurs when number of intersections is close to or lower than the
number of fractures). The original fractures (which are few) are
kept. That is, the sub-zone in question is not simplified.
[0121] Once these equivalent permeability calculations are carried
out for each sub-zone, the other equivalent flow parameters
characterizing the simplified sub-zones are readily determined
according to the following methods and equivalences:
[0122] Calculation of a first equivalent network (so-called Warren
and Root parallelepipedic network), which is referred to as "fine",
directly resulting from the method of French Patent 2,757,957
corresponding to U.S. Pat. No. 6,064,944. This network (FIG. 4) is
characterized by spacings of fractures s.sub.1.sup.fin,
s.sub.2.sup.fin in the 2 orthogonal directions of principal
permeability 1 and 2 defining the fracture network.
[0123] An additional parameter, the opening of the fractures
(e.sup.fin), characterizes the fractures of this fine network. The
value of the fracture openings is in practice nearly always
negligible in relation to the fracture spacing. This hypothesis is
taken into account in the following formulas, where the same
opening value is assumed for the 2 fracture families. Considering
the equality of porosities of the initial network DFN
(.quadrature..sub.f) and of the fine equivalent network, e.sup.fin
is deduced from the fracture volume of the initial network DFN,
V.sub.f.sup.init, and from the total rock volume V.sub.T as
follows:
e fin = 1 ( 1 s 1 fin + 1 s 2 fin ) V f init V T = 1 ( 1 s 1 fin +
1 s 2 fin ) .phi. f ##EQU00004##
[0124] As a matter of interest, the principal equivalent fracture
permeabilities obtained from the aforementioned calculations are
k.sub.1=k.sub.eq.sup.Max and k.sub.2=k.sub.eq.sup.Min in the
principal directions 1 and 2. The conductivities of the fractures
of the fine equivalent network, C.sub.f1.sup.fin and
C.sub.f2.sup.fin, in these two directions of flow are deduced by
writing the conservation of the flows per unit area of fractured
medium:
C.sub.f1.sup.fin=s.sub.2.sup.fink.sub.1 and
C.sub.f2.sup.fin=s.sub.1.sup.fink.sub.2
[0125] Finally, the matrix medium between fractures has a
permeability k.sub.m.sup.fin.
[0126] Replacement of this fine network (FIG. 4) by the so-called
"coarse" equivalent network (FIG. 6) comprises more spaced-out
fractures to increase the degree of simplification with a view to
later flow simulations. The geometric and flow properties of this
coarse network are as follows:
[0127] fracture spacings s.sub.1.sup.gros and s.sub.2.sup.gros such
that:
s.sub.1.sup.gros=Gs.sub.1.sup.fin
s.sub.2.sup.gros=Gs.sub.2.sup.fin,
[0128] where G is a (fracture spacing) magnification coefficient of
the network whose value is left to the user's discretion, with
however an upper limit G.sub.max-zone that should not be exceeded
to guarantee sufficient connectivity between simplified and
non-simplified zones:
[0129] G<G.sub.max-zone where G.sub.max-zone is such that
Max(s.sub.1.sup.gros,s.sub.2.sup.gros)<(minimum lateral
dimension of the sub-zone)/6
[0130] Thus:
G max - zone = DLM 6 Max ( s 1 fin , s 2 fin ) ##EQU00005##
[0131] with:
[0132] DLM is a minimum lateral dimension of the given
sub-zone;
[0133] s.sub.1.sup.fin and s.sub.2.sup.fin are fracture spacings in
the so-called Warren and Root representation.
[0134] fracture conductivities C.sub.f1.sup.gros and
C.sub.f2.sup.gros have values allow keeping the flows per unit area
of fractured medium, that is also the equivalent permeabilities,
that is:
C.sub.f1.sup.gros=s.sub.2.sup.grosk.sub.1 and
C.sub.f2.sup.gros=s.sub.1.sup.grosk.sub.2, or,
knowing that C.sub.f1.sup.fin=s.sub.2.sup.fink.sub.1 and
C.sub.f2.sup.fin=s.sub.1.sup.fink.sub.2,
C.sub.f1.sup.gros=GC.sub.f1.sup.fin and
C.sub.f2.sup.gros=GC.sub.f2.sup.fin
[0135] A fracture opening e.sup.gros allows again keeping the
fracture porosity .phi..sub.f of the initial network which is equal
to that of the coarse equivalent network:
.phi. f = e gros ( 1 / s 1 gros + 1 / s 2 gros ) = e fin ( 1 / s 1
fin + 1 / s 2 fin ) ##EQU00006## hence : e gros = e fin 1 s 1 fin +
1 s 2 fin 1 s 1 gros + 1 s 2 gros = G e fin ##EQU00006.2##
[0136] a matrix permeability k.sub.m.sup.gros keeps the value of
the matrix-fracture exchange parameter:
.lamda. fin = r w 2 k m fin k f fin ( .alpha. s 1 fin 2 + .alpha. s
2 fin 2 ) = .lamda. grossier = r w 2 k m gros k f gros ( .alpha. s
1 gros 2 + .alpha. s 2 gros 2 ) ##EQU00007##
where .alpha. is a constant and where the fracture equivalent
permeabilities of the fine and coarse networks are equal and
denoted by k.sub.f.sup.fin and k.sub.f.sup.gros,
[0137] That is:
k m gros = k m fin 1 S 1 fin 2 + 1 S 2 fin 2 1 S 1 gros 2 + 1 S 2
gros 2 = G 2 k m fin ##EQU00008##
[0138] Finally, once this fine network--.fwdarw.coarse network
equivalence operation achieved for each sub-zone (or "block" of
ZP), the fractures of the simplified networks obtained are extended
outside the limits of sub-zones (or "blocks") in order to guarantee
sufficient partial "covering" and therefore sufficient horizontal
connectivity of the simplified networks of neighboring sub-zones
(or "blocks" of ZP). Therefore, by following a test-proven
procedure, the fractures of the simplified network can thus be
extended by a length equal to 60% of the maximum spacing
(s.sub.1.sup.gros,s.sub.2.sup.gros) of the fractures of this
network.
[0139] Such an image is represented in FIG. 6.
[0140] Calibration of the Flow Properties of the Fractures
[0141] The next stage is the calibration of the flow properties of
the fractures (fracture conductivity and opening), locally around
the wells. This requires a well test simulation. According to the
invention, this well test simulation is performed on the simplified
flow models (FIG. 6).
[0142] This type of calibration is well known. The method described
in French Patent 2,787,219 can for example be used. The flow
responses of some wells (transient or pseudo-permanent flow tests,
interferences, flow rate measurement, etc.) are simulated on these
models extracted from the geological model giving a discrete
(realistic) representation of the fractures supplying these wells.
The simulation result is then compared with the real measurements
performed in the wells. If the results differ, the statistical
parameters (PSF) describing the fracture networks are modified,
then the flow properties of the initial fractures are redetermined
and a new simulation is carried out. The operation is repeated
until the simulation results and the measurements agree.
[0143] The results of these simulations allow calibration
(estimation) of the geometry and the flow properties of the
fractures, such as the conductivities of the fracture networks of
the reservoir being studied and the openings.
[0144] 3--Simulation of the Fluid Flows (SIM) and Optimization of
the Reservoir Production Conditions (OPT)
[0145] At this stage, the reservoir engineer has all the data
required to construct the flow model on the reservoir scale. In
fact, fractured reservoir simulations often adopt the
"double-porosity" approach proposed for example by Warren J. E. et
al. in "The Behavior of Naturally Fractured Reservoirs", SPE
Journal (September 1963) at pages 245-255, according to which any
elementary volume (cell of the reservoir model) of the fractured
reservoir is modelled in a form of a set of identical
parallelepipedic blocks, referred to as equivalent blocks,
delimited by an orthogonal system of continuous uniform fractures
oriented in the principal directions of flow. The fluid flow on the
reservoir scale occurs through the fractures only, and fluid
exchanges take place locally between the fractures and the matrix
blocks. The reservoir engineer can for example use the methods
described in the following documents, applied to the entire
reservoir this time: French Patent 2,757,947 corresponding to U.S.
Pat. No. 6,023,656 and French Patent 2,757,957 corresponding to
U.S. Pat. No. 6,064,944, and EP Patent 2,037,080. These methods
allow calculation of the equivalent fracture permeabilities and the
equivalent block dimensions for each cell of the reservoir
model.
[0146] The reservoir engineer chooses a production process, for
example the waterflooding recovery process, for which the optimum
implementation scenario remains to be specified for the field being
considered. The definition of an optimum waterflooding scenario is
for example the setting of the number and the location (position
and spacing) of the injector and producer wells in order to best
account for the impact of the fractures on the progression of the
fluids within the reservoir.
[0147] According to the scenario being selected, that is the
double-medium representation of the reservoir and to the formula
relating the mass and/or energy exchange flow to the
matrix-fracture potential difference, it is then possible to
simulate the expected hydrocarbon production by means of the flow
simulator (software) referred to as double-medium simulator.
[0148] At any time t of the simulated production, from input data
E(t) (fixed or simulated-time varying data) and from the formula
relating exchange flow (f) to potential difference (.DELTA..PHI.),
the simulator solves all the equations specific to each cell and
each one of the two grids of the model (equations involving the
matrix-fracture exchange formula described above), and it thus
delivers the values of solution to the unknowns S(t) (saturations,
pressures, concentrations, temperature, etc.) at this time t. This
solution provides knowledge of the amounts of oil produced and of
the state of the reservoir (pressure distribution, saturations,
etc.) at the time being considered.
[0149] 4--Optimized Reservoir Development (EXPLO)
[0150] Selecting various scenarios characterized, for example, by
various respective sites for the injector and producer wells, and
simulating the hydrocarbon production for each one according to
stage 3, enables selection of the scenario allowing the production
of the fractured reservoir being considered to be optimized
according to the technico-economic selected criteria.
[0151] Then the reservoir is developed according to this scenario
allowing the reservoir production to be optimized.
* * * * *